1. Technical Field
The present invention relates to the field of processes for the deacidification of gaseous effluent. The invention advantageously applies to the treatment of gas of industrial origin and natural gas.
2. Description of the Art
Absorption processes employing an aqueous solution of amines are commonly used to remove the acidic compounds (in particular CO2, H2S, COS, CS2, SO2 and mercaptans) present in a gas. The gas is deacidified by being brought into contact with the absorbent solution and then the absorbent solution is thermally regenerated. For example, the document U.S. Pat. No. 6,852,144 describes a method for removing the acidic compounds from hydrocarbons. The method uses an absorbent solution formed of water/N-methyldiethanolamine or water/triethanolamine comprising a high proportion of a compound belonging to the following group: piperazine and/or methylpiperazine and/or morpholine.
A limitation of the absorbent solutions commonly used in deacidification applications is an inadequate selectivity for absorption of H2S with respect to CO2. This is because, in some cases of deacidification of natural gas, selective removal of H2S is desired, while limiting as much as possible the absorption of CO2. This constraint is particularly important for gases to be treated already comprising a CO2 content lower than or equal to the desired specification. A maximum H2S absorption capacity, with a maximum H2S absorption selectivity with respect to CO2, is then desired. This selectivity makes it possible to maximize the amount of treated gas produced and to recover an acid gas at the regenerator outlet having the highest possible H2S concentration, which limits the size of the units of the sulfur line downstream of the treatment and guarantees a better operation. In some cases, an H2S enriching unit is necessary in order to concentrate the acid gas in H2S. In this case, the most selective amine is also desired. Tertiary amines, such as N-methyldiethanolamine, or hindered amines exhibiting slow kinetics of reaction with CO2 are commonly used but exhibit limited selectivities at high H2S loading contents.
Another limitation of the absorbent solutions commonly used in total deacidification applications is excessively slow kinetics for capture of CO2 or COS. In the case where the specifications desired with regard to CO2 or COS are very severe, the fastest possible reaction kinetics are desired so as to reduce the height of the absorption column, this item of equipment under pressure, typically between 20 and 90 bar, representing a major part of the capital costs of the process.
Whether maximum kinetics for capture of CO2 and COS in a total deacidification application or minimum kinetics of capture of CO2 in a selective application is being sought for, it is always desirable to use an absorbent solution having the greatest possible cyclic capacity. This cyclic capacity, denoted Δα, corresponds to the difference in loading content (α denoting the number of moles of acid compounds absorbed nacid gas per kilogram of absorbent solution) between the absorbent solution feeding the absorption column and the absorbent solution withdrawn at the bottom of said column. This because the more the absorbent solution has a high cyclic capacity, the more limited is the flow rate of absorbent solution which is necessary to employ to deacidify the gas to be treated. In gas treatment processes, the reduction in the flow rate of absorbent solution also has a strong impact on the reduction in capital costs, in particular with regard to the size of the absorption column.
Another essential aspect of the operations for the treatment of industrial gases, or flue gases, by a solvent remains the regeneration of the separating agent. According to the type of absorption (physical and/or chemical), a regeneration by reduction in pressure and/or by distillation and/or by entrainment by vaporized gas, known as “stripping gas”, is generally envisaged.
Another limitation of the absorbent solutions commonly used today is an energy consumption necessary for the regeneration of the solvent which is too high. This is particularly true in the case where the partial pressure of acid gases is low. For example, for a 30% by weight aqueous solution of 2-aminoethanol (or monoethanolamine or ethanolamine or MEA) used to capture CO2 in postcombustion in a power plant flue gas, where the CO2 partial pressure is of the order of 0.12 bar, the regeneration energy represents approximately 3.7 GJ per tonne of CO2 captured. Such an energy consumption represents a considerable operating cost for the process for capturing CO2.
It is well known to a person skilled in the art that the energy necessary for the regeneration by distillation of an amine solution can be broken down according to three different headings: the energy necessary to reheat the solvent between the top and the bottom of the regenerator, the energy necessary to lower the acid gas partial pressure in the regenerator by vaporization of a stripping gas and, finally, the energy necessary to break the chemical bond between the amine and the CO2.
These first two headings are inversely proportional to the flow rates of absorbent solution which it is necessary to circulate in the unit to achieve a given specification. In order to reduce energy consumption associated with the regeneration of the solvent, it is thus preferable yet again to maximize the cyclic capacity of the solvent.
It is difficult to find compounds, or a family of compounds, which make/makes it possible for the various deacidification processes to operate at reduced operating costs (including the regeneration energy) and capital costs (including the cost of the absorption column).
It well known to a person skilled in the art that tertiary amines or secondary amines with severe steric hindrance have slower kinetics for capture of CO2 than primary or secondary amines exhibiting relatively little hindrance. On the other hand, tertiary or secondary amines with a severe steric hindrance have instantaneous kinetics for capture of H2S, which makes it possible to carry out a selective removal of H2S based on distinct kinetic performances.
Among the applications of these tertiary or hindered amines, the document FR 2 100 475 describes a process for the selective absorption of sulfur-comprising gases by an absorbent compound in aqueous solution, the compound having a general formula which may comprise a tertiary amine, one of the substituents of which comprises an ether functional group, but excluding alkanolamines.
The U.S. Pat. No. 4,405,811 describes a process for the selective removal of H2S in gases comprising H2S and CO2 by an absorbent comprising amines of tertiary alkanolamine type which may or may not comprise one or more ether functional groups which, in this case, necessarily occur on the hydroxylated substituent.